This application is a 371 application of PCT/N00/00018 filed Jan. 26, 2000.
The present invention relates to a method for removing and recovering CO2 from exhaust gas from a power and/or heat generating plant by chemical absorption and desorption for deposition as convenient at the location.
Due to the environmental aspects of CO2 as a gas with greenhouse effect, and taxes on the emission of CO2 by some national governments, the possibility of reducing the emissions of CO2 to the atmosphere from a power and/or heat generating processes, in particular from exhaust gas from gas turbines offshore, in a way that implies reduced energy consumption and investment costs, has been widely discussed.
Conventional power and/or heat generating processes, using carbon containing fuels and where the oxygen source is air, have carbon dioxide concentrations of 3-15% in the combustion products, hereinafter called exhaust gas, dependent on the fuel and the combustion and heat recovery process applied. E.g. in natural gas fired gas turbines the concentration of CO2 in the exhaust gas is only 3-4%. Thus, a reduction in the emission of carbon dioxide to the atmosphere makes it necessary to separate the carbon dioxide from the exhaust gas because it will be too expensive to compress and deposit the whole exhaust gas. The compression of the recovered CO2 for deposition in e.g. a geological formation is an implied part of any recovery method.
The concentration of carbon dioxide in the exhaust gas may be raised to higher levels by recirculating exhaust gas suggested by e.g. Chiesa et al. (paper presented at the International Gas Turbine and Aeroengine Congress and Exhibition Stockholm, Sweeden-Jun. 2-5, 1998) in a coal based Integrated Gasification and Combined Cycle (IGCC) plant or described by Ronning et al. in Norwegian patent 180520.
CO2 can be removed from exhaust gas by means of several separation processes, e.g. chemically active absorption processes, physical absorption processes, adsorption by molecular sieves, membrane separation, and cryogenic techniques. Chemical absorp-tion by means of alkanolamines is presently considered the most practical and economical method to separate CO2 from exhaust gas at near atmospheric pressure. In fact MEA (monoethanolamine) is the absorption medium that dominates due to its high affinity for CO2 even at low partial pressure of CO2.
The application of MEA for absorbing CO2 from exhaust gas has been described in the literature by Pauley et al. (Proceedings of the Gas Conditioning Conference, Norman, Ok, Mar. 5-7, 1984, paper H; an abbreviated version in Oil and Gas J., May 14, 1984, p 87-92). They describe a CO2 removal system based on MEA with additives. There are, however, descriptions of corrosion problems. MEA degradation, and high chemicals consumption. In the described method the exhaust gas pressure was essentially atmospheric with typically 8.5% CO2 in the feedstream to the absorber. This represents a higher CO2 partial pressure than will be experienced in gas turbine exhaust gas.
It is further known (see e.g. Fang-Yuan Jou et al., Can.J.Chem.Eng., 1993, vol 71, April, 264-268) that use of other amines than MEA, particularly tertiary amines like MDEA (methyidiethanolamine) is less prone to degradation, and its vapor pressure is lower than MEA""s leading to lower losses of amine vapor with the gas streams leaving. The corrosion problems are also lower than if MEA is used. The use of tertiary amines, however, for treating gas turbine exhaust gas is to day uneconomical due to these amines"" lower affinity for CO2 compared to MEA. Hence CO2 removal from exhaust gas is done by absorption in a more reactive amine like MEA. The application of MDEA requires that exhaust gas is compressed to an elevated pressure to increase the partial pressure of CO2 since this increases the possible loading (mol CO2/mol amine) of CO2 in the MDEA solution.
These low pressure MEA-based CO2 absorption processes require heavy and voluminous equipment. Furthermore, corrosion in the process equipment, degradation of the amine due to the temperature levels normally used, and generally high consumption of chemicals (e.g. amine) are major problems in these processes.
Furthermore, these processes will consume a substantial amount of heat and/or power. The application of the Selexol process, commercialised by Union Carbide, is suggested by Chiesa et al. (paper presented at the International Gas Turbine and Aeroengine Congress and Exhibition Stockholm, Sweden-Jun. 2-5, 1998) to recover CO2 from a coal based Integrated Gasification and Combined Cycle (IGCC) plant. This process, however, needs a very high feed gas pressure. Chiesa et al estimated that an operating pressure of minimum 41 bar is needed to recover 90% CO2 from exhaust gas when CO2 in the exhaust gas was about 20%. They considered that at least 50 bar was required to obtain a reasonable driving force for mass transfer. To achieve this pressure, a partly inter cooled compressor is used. The pressurised exhaust gas is cooled to near ambient temperature by a recuperative heat exchanger, and ducted to the absorption column where CO2 is captured by Selexol. The nitrogen-rich CO2 depleted exhaust gas, exiting the Selexol process, is heated to about 600xc2x0 C. in the gasification down stream process and is further expanded with reheating between stages. The drawback of the process scheme suggested by Chiesa et al., is the required absorption pressure of 50 bar which reduces the efficiency of the process and prevent efficient use of available process heat.
Australian patent AU 9,728,540-A relates to a process for treating a high-pressure raw gas selected from high-pressure natural gas and various synthesis gases with a carbon dioxide absorbing fluid, whereby highly concentrated carbon dioxide is almost fully removed from the raw gas to obtain a refined gas having a carbon dioxide concentration of 10 to 10000 ppm, and moreover for recovering carbon dioxide partially at high-pressure from the absorbing fluid as well as a system therefore.
The Australian patent teaches partial desorption of CO2 at elevated pressure which is defined in that patent as at least 2 kp/cm 2 abs (approximately 2 bar). The referred patent further limits the desorption pressure in its first separator to the pressure of the absorber which in most cases makes it impossible to condense recovered CO2 by cooling water which is an advantage if CO2 shall be compressed to the required pressure for deposition in a geological formation. Typically this would require 50 bar or above. The Australian patent defines any pressure above 2 bar as high pressure. Carryover of the active part (typically an alkanolamine) of the aqueous solution may take place from the first gas-liquid separator in the described process, and this may also be a problem in conventional absorption/desorption systems. The Australian patent specifies 90xc2x0 C. to 150xc2x0 C. as the temperature level at which CO2 is partially desorbed at elevated pressure in their first desorption stage. Energy to preheat the absorbent must be available at a few degrees higher, typically 10 degrees or more. The temperature level needed in their reboiler (12) in their FIG. 1 is dictated by the boiling point of the CO2-free absorbent plus an increase to provide driving force.
The main object of the present invention was to arrive at an improved method for removing and recovering CO2 from exhaust gas from a power and/or heat generating process by chemical absorption and desorption in a way that implies reduced weight and volume of the equipment used in the absorption and desorption process.
Another object of the present invention was to arrive at an improved method for removing and recovering CO2 from exhaust gas from a power and/or heat generating process by chemical absorption and desorption in a way that implies more efficient use of other amines than MEA compared to previously known CO2 absorption and desorption methods.
A further object of the invention was to arrive at an improved method for removing and recovering CO2 from exhaust gas from a power and/or heat generating process by chemical absorption and desorption which has low consumption of chemicals and insignificant corrosion and degradation problems compared to previously known methods.
Furthermore, yet another object of the present invention was to arrive at an improved method for removing and recovering CO2 from exhaust gas from a power and/or heat generating process by chemical absorption and desorption which reduces the power needed to compress the recovered CO2 stream to deposition pressure.
In view of the above mentioned problems associated with removing and recovering CO2 from exhaust gas from a power and/or heat generating process by chemical absorption and desorption, research has been made.
The inventors found that the problems mentioned above can be solved if the exhaust gas stream from a power and/or heat generating process is recompressed to between 5 and 30 bar and more preferably between 7 and 20 bar before entering the CO2 absorption unit, and that this recompression implies that an improved absorption and desorption process is achieved which eliminates the problems mentioned above connected to previously known techniques.
The inventors found a method for removing and recovering CO2 from exhaust gas from a power and/or heat generating plant (a main power plant) by chemical absorption and desorption respectively, where the exhaust gas is fed to an absorber containing a chemical absorbent where the CO2 is absorbed in said absorbent and a CO2-depleted exhaust gas stream is formed, and the CO2 rich absorbent is further fed to a desorber where CO2 is removed from the absorbent, and the absorbent essentially free of C02 is recirculated to the absorber and the desorbed CO2 gas is discharged off, where the exhaust gas is cooled and recompressed to an elevated pressure, in a compressor in a secondary power plant integrated with the main power plant, said absorber and said desorber, before entering the absorber, and that the CO2-depleted exhaust gas emerging from the absorber is reheated and further expanded in an expander in said secondary power plant.
Recompression of exhaust gas will consume a substantial amount of power. The power consumption will, however, be reduced substantially if a gas turbine or an inter-cooled compressor and expander system, i.e. a Brayton cycle, hereinafter called the secondary power system, is integrated with the power and/or heat generating plant, hereinafter called the main power system, and the CO2 absorption unit which may then be in an improved absorption and desorption process. The Brayton cycle. which is a compression and expansion process, is the basis of all gas turbine cycles.
According to the present invention, exhaust gas from the main power system is cooled and compressed (optionally with intercooling between the stages) in the secondary power system. The compressed exhaust gas containing CO2 is cooled and is fed to an absorber unit in the CO2 absorption and desorption system according to the present invention. The CO2-depleted exhaust gas emerging from the absorber unit is in the secondary power system re-heated and expanded to near atmospheric pressure thus generating power to compress the CO2 containing exhaust gas entering the absorber unit. The number of intercooled compressor stages, the recompression pressure, and the reheating temperature is selected in such a way that the expansion turbine at least generate enough power to drive the compressor.
In the above mentioned absorber unit the exhaust gas is first fed to an absorption column where it is contacted with an absorbent that picks up most of the CO2. The CO2 rich absorbent from the absorption unit is pumped as required to desorption pressure which may be higher than the absorption pressure. The temperature in the rich absorbent is raised to the level needed to render CO2 on desorption at a pressure facilitating condensation by cooling water, typically this would require 50 bar or above.
After increasing/raising the temperature in the rich absorbent stream, the stream is fed to a first gas-liquid separator before entering the desorption unit.
To avoid undue carryover of the active part (typically an alkanolamine) in the absorbent, the first gas-liquid separator has a dephlegmator (i.e. condensator with reflux) installed in the gas stream. In this dephlegmator a condensed liquid phase separation will take place leaving mostly water in the CO2 since the active part is less volatile than water. The condensed phase will flow back into the separator.
A similar arrangement is made over the top of the desorption column. The energy taken out in the dephlegmators is foreseen recovered.
Further, the desorber is equipped with a side reboiler at a place where there is still CO2 in the absorbent and the temperature is thus lower than it would be if dictated by the vapour pressure of the absorbent solution alone. This lower temperature facilitates use of energy at a lower temperature than if a bottom reboiler is used where very little CO2 is present. The last reboil effect is provided by live steam.
The use of the dephlegmators allows the use of higher temperature in the desorption units than in conventional desorption units without losing more active absorbent. The dephlegmators also provides water outlets which give more freedom to use live steam than in a conventional absorption-desorption system. Live steam enables use of lower temperature steam than would be required if the temperature difference in a heat exchanger had to be overcome.
The pressure of the recovered CO2 is attained by use of thermal energy through desorption of CO2 at a higher pressure created by applying a higher temperature in the desorber than conventionally used. The enabling factor is the operation of the absorption column at pressure which follows from exhaust gas recompression. In spite of the energy recovery from the pressurised, CO2-depleted exhaust gas, this represents a finite energy consumption which implies efficiency loss for the overall energy conversion process. Hence, the exhaust gas recompression and thus the absorption column pressure should be kept to a minimum.
Selecting the right combination of recompression pressure and reheating temperature is a very important factor in order to achieve an efficient process according to the present invention. Increased reheating temperature combined with a slightly increased cycle pressure ratio will increase process efficiency. This applies to all gas turbine cycles according to the principle of the Brayton cycle. Reheating can be accomplished by using available heat in the hot exhaust gas generated in the main power system. The reheating temperature in this case is limited to the hot exhaust gas temperature which normally is below 500-700xc2x0 C. Additional firing in the main power system to heat the compressed, CO2-depleted exhaust gas in the secondary power system will increase the fuel to power efficiency further, because this will both increase the concentration of CO2 in the exhaust gas and allow a higher reheating temperature. The trade-off between the two reheating cases is higher investment cost but improved efficiency in the additional firing case versus less expensive equipment but lower efficiency in the hot exhaust gas reheating case. In both cases heat supplied to the compressed CO2-depleted exhaust gas can be recovered as power at high efficiency in a turbine by depressurising the gas.
By this method the overall process efficiency may be in the same order as if CO2 is removed and recovered at atmospheric pressure, but the high absorption pressure will reduce the size of the CO2 removal and recovery system substantially since the gas volume becomes smaller when the gas is compressed, and the driving force for the absorption becomes larger. There is accordingly a reduction in both tower diameter and height in the absorption column. The volume and weight of the desorption column may also be reduced if the higher partial pressure of CO2 in the gas leaving the absorption column is exploited to leave more CO2 in the regenerated (lean) absorbent. Alternatively, this could be exploited to increase the CO2 recovery.
The high pressure also makes it technically and economically feasible to select other alkanolamines than MEA. Other alkanolamines may then be found which are more energy efficient, less corrosive and less prone to degeneration, e.g. MDEA. Elevated pressure in the absorber enables the use of tertiary amines for absorbing the CO2, and this eliminates the corrosion and degradation problems associated with the use of MEA as the chemically active part of the absorbent.
Recovery of CO2 at elevated pressure will also reduce the work required to compress CO2 before injection and deposition.
Recirculation of exhaust gas in the main power system will improve the electric power efficiency further.
The high partial pressure of CO2 at the absorption tower bottom also allows a higher loading of CO2 on the alkanolamine which reduces the absorbent circulation rate required to effect CO2-removal.
The method according to the invention provides separation of absorbent and water in the desorber section overhead streams thus providing extra freedom to allow live steam to be used in the stripping column. Using live steam for the highest temperature heat effect means its temperature level may be reduced by the driving force otherwise used for indirect heat. This feature, and the use of a side reboiler, allows the use of a heating medium at lower temperature than normally employed by such processes.